One or more implementations described herein generally relate to Moineau-type pumps and motors inclusive of positive displacement or progressive cavity motors and pumps. Such implementations that may be used when drilling the wellbore of a subterranean well. More particularly, one or more such implementations may incorporate a flow restrictor arranged and designed to limit bypass flow through the bearings or bearing section of Moineau-type pumps and/or motors.
Wellbores are frequently drilled into the Earth's formation to recover deposits of hydrocarbons and other desirable materials trapped beneath the Earth's surface. A well may be drilled using a drill bit coupled to the lower end portion of what is known in the art as a drill string. The drill string has a plurality of joints of drill pipe that are coupled together end-to-end using threaded connections. The drill string is rotated by a rotary table or top drive at the surface, which may also rotate the coupled drill bit downhole. Drilling fluid or mud is pumped down through the bore of the drill string and exits through ports at or near the drill bit. The drilling fluid serves to both lubricate and cool the drill bit during drilling operations. The drilling fluid also returns cuttings to the surface via the annulus between the drill string and the side wall of the wellbore. At the surface, the drilling fluid is filtered to remove the cuttings.
A bottom hole assembly (BHA) is often disposed in drilling string toward the lower end portion thereof. The BHA is a collection of drilling tools and measurement devices and may include the drill bit, any directional or formation measurement tools, deviated drilling mechanisms, mud motors (e.g., Moineau pumps/motors) and weight collars. A measurement while drilling (MWD) or logging while drilling (LWD) collar is often positioned just above the drill bit to take measurements relating to the properties of the formation as the wellbore is being drilled. Measurements recorded from MWD and LWD systems may be transmitted to the surface in real-time using a variety of methods known to those skilled in the art. Once received, these measurements assist operators at the surface in making decisions relating to the drilling operation.
Directional drilling is the intentional deviation of the wellbore from the path that it would naturally take. In other words, directional drilling is the steering of the drill string so that the drill string travels in the desired direction. Directional drilling can be advantageous in offshore drilling because directional drilling permits several wellbores to be drilled from a single offshore drilling platform. Directional drilling also enables horizontal drilling through the formation, which permits a longer length of the wellbore to traverse the reservoir and may permit increased hydrocarbon production. Directional drilling may also be beneficial in drilling vertical wellbores. Often, the drill bit will veer off of an intended drilling trajectory due to the sometimes unpredictable nature of the underground formation and/or the forces the drill bit experiences. When such deviation occurs, a directional drilling system may be employed to return the drill bit to its intended drilling trajectory.
A common directional drilling system and its method of use employ a BHA that includes a bent housing and a Moineau motor/pump, which is also known as a positive displacement motor (PDM) or mud motor. The bent housing includes an upper section and lower section formed on the same section of drill pipe, but the respective sections are separated by a bend in the pipe. The bent housing with the drill bit coupled thereto is pointed in the desired drilling direction. The mud motor is employed to rotate the bent housing and thereby rotate the drill bit to drill in the desired direction.
A mud motor converts some of the energy from the flow of drilling fluid or mud downward through the bore of the drill string into a rotational motion that drives the drill bit. Thus, by maintaining the bent housing at the same azimuth relative to the borehole, the drill bit will drill in a desired direction. When straight drilling is desired, the entire drill string, including the bent housing, is rotated from the surface by the rotary table or top drive, as previously described. The drill bit may angulate with the bent housing and therefore may drill a slight overbore, but straight, wellbore.
PDM power sections include a rotor and a stator. The stator may be a metal tube, e.g., steel, with a rubber or elastomer molded and disposed to an inner surface thereof to form a multi-lobed, helixed interior profile. The stator tube may be cylindrical inside (having a rubber or elastomer insert of varying thickness), or may have a similar multi-lobed, helixed interior profile disposed therein so that the molded-in rubber/elastomer is of a substantially uniform thickness (i.e., even wall). Whether solid rubber/elastomer or even wall, power sections are generally uniform throughout their length. That is, they are either all rubber/elastomer or all even wall over the entire length of the multi-lobed, helixed interior profile. The rotor may also be constructed of a metal, such as steel, with a solid or hollow inner construction. The rotor may have a multi-lobed, helically-shaped outer surface, which compliments the inner surface of the stator. The rotor may also have a rubber or elastomer disposed on its outer surface. The outer surface of the rotor has one less lobe than the inner surface of the stator such that a moving, fluid-filled chamber is formed between the rotor and the stator as fluid is pumped through the motor.
The rotor rotates and gyrates in response to a fluid (e.g., drilling fluid or mud) pumped downhole through the drill string and stator of the PDM. Below the power section, the PDM has a bearings section. The bearing section has a housing that is coupled to the stator via a cross-over housing rigidly coupled between them. A drive shaft is positioned within the bearing section housing and couples to a lower end portion of the rotor via a connecting rod. The connecting rod, which may have an upset section on each end portion thereof, translates the rotation and gyration of the rotor to the true rotation of the drive shaft. Upper and lower connections couple to the upset sections of the connecting rod to the rotor and to the drive shaft.
The bearing section contains a plurality of bearings which act to transfer the load of the drill string from the bearing section housing to the drive shaft and bit. Another function of the drilling fluid flow discussed above with respect to the bit is the use of drilling fluid to lubricate and cool the bearings. A general problem of employing drilling fluid to lubricate and cool the bearings has been erosion and wear of the bearings themselves by the fluid flow. In pumps/motors in which radial bearings serve double duty as flow restrictors, the radial bearings wear on their diameters due to side loading and thus their flow-restricting characteristics change over time. Therefore, flow restrictors are generally employed in drilling fluid lubricated/cooled bearings to restrict the bypass of fluid through the bearing section to a relatively small percentage of the total flow so as to maintain the fluid flow through the bit nozzles at a sufficient rate to effectively remove cuttings and cool the bit cutters. If the bearings or flow restrictors wear excessively, the drill string (and motor) may have to be tripped from the wellbore to enable repair of the bearings after an uneconomically short period of drilling time (e.g., when the bit is still in satisfactory condition for further drilling).